The treatment of subterranean formations penetrated by a wellbore to stimulate the production of hydrocarbons or to enhance the ability of the formation to accept injected fluids has long been known in the art. One of the most common methods is to subject the formation to a fracturing treatment. This treatment is conducted by injecting a liquid, gas, or two-phase fluid, which generally is referred to as a fracturing fluid, down the wellbore at sufficient pressure and flow rate to fracture the subterranean formation. A proppant material such as sand, fine gravel, sintered bauxite, glass beads, or the like may also be introduced into the fractures to keep the fractures at least somewhat open (“propped”) once the fracturing pressure is released. Propped fractures provide larger flow channels through which an increased quantity of a hydrocarbon may flow, thereby increasing the productive rate of a well.
The rheological requirements of a fracture fluid are highly constraining. To adequately propagate fractures in the subterranean formation, a fracturing fluid should exhibit a low leakage rate of liquids into the formation during the fracturing operation. Also, the fracturing fluid should have sufficient body and viscosity to transport and deposit proppant into the cracks in the formation formed during fracturing. The fracturing fluid should readily flow back into the wellbore after the fracturing is complete and leave minimal residue that could impair permeability and conductivity of the formation. Finally, the fracturing fluid should have rheological characteristics that permit it to be formulated and pumped down the wellbore without excessive difficulty or pressure drop friction losses.
Several techniques have evolved for treating a subterranean well formation to stimulate hydrocarbon production. For example, hydraulic fracturing methods have often been used according to which a portion of a formation to be stimulated is isolated using conventional packers, or the like, and a stimulation fluid containing gels, acids, sand slurry, and the like, is pumped through the well bore into the isolated portion of the formation. The pressurized stimulation fluid pushes against the formation at a very high force to establish and extend cracks on the formation. However, the requirement for isolating the formation with packers is time consuming and considerably adds to the cost of the system.
One of the problems often encountered in hydraulic fracturing is fluid loss which for the purposes of this application is defined as the loss of the stimulation fluid into the porous formation or into the natural fractures existing in the formation. The most commonly used fracturing fluids are water-based compositions containing a hydratable high molecular weight polymeric gelling material that increases the viscosity of the fluid. Thickening the fluid reduces leakage of liquids from the fracture fissures into the formation during fracturing and increases proppant suspension capability.
However, a significant number of hydrocarbon bearing subterranean formations do not respond to conventional fracturing fluids. These problematic formations include hydrocarbon reservoirs that are under low pressure, subterranean formations that exhibit low permeability to fluid flow, and formations in which permeability is reduced when exposed to water. For example, clay in formations swells when it absorbs water that reduces permeability. Also, fracturing fluids do not readily flow back out of these difficult formations when the fracturing operation is complete; the fluids remain in the formations and tend to impede the flow of hydrocarbons to the wellbore.
Foamed fracturing fluids are known as an alternative to the conventional all-liquid fracturing fluids and can be designed to meet the desired rheological requirements and to be effective for problematical formations. Foamed fracturing fluids are media in which a relatively large volume of gas is dispersed in a relatively small volume of liquid, usually with the aid of a foaming agent that reduces the surface tension of the fluids and stabilizes small bubbles. The most commonly used gases for foamed fracture fluids, nitrogen and carbon dioxide, are noncombustible, readily available, and relatively cheap. Most commonly used foamed fracturing fluids are water based, although oil and alcohol based foams are known.
Foamed fracture fluids may be superior to conventional liquid fracturing fluids for problematic formations because foams contain less liquid than traditional fracturing fluids and thus have less liquid to retrieve after the fracturing operation is complete. Moreover, the expansion of the gas in the foamed fluid when fracturing pressure in the wellbore is relieved promotes flow of residual fracture fluid liquid back into the wellbore. Moreover, foamed fracturing fluids exhibit low liquid leakage into the formation because they inherently have low liquid concentrations, and the stable two-phase structure characteristic of foams minimizes leakage and promotes proppant transport and placement capability.
The most common foaming agents are ionic surfactants. However, ionic surfactants can have compatibility issues with both problematic formations and other additives within a foamed fracturing fluid or subsequent treatment fluid. For example, sandstone and limestone formations have negative surface charges. Thus, when a cationic foaming agent is used in a foamed fracturing operation, the cationic foaming agent may coat the surfaces of the formation leaving the formation oil-wet and/or adversely affect subsequent operations like consolidation and scale-inhibiting operations. In addition, ionic surfactants may be rendered ineffective in the presence of high salt concentrations, and thus are incompatible with brine treatment fluids.
Thus, a need exists for a foam fracturing system that can provide viscosity while stabilizing the foam structure without, or with minimal use of additional foam surfactants.